Subterranean wellbore formations serve various purposes including, for example, extraction of oil and gas from the subterranean formation and extraction of geothermal heat from the subterranean formation. Wellbores may be formed in a subterranean formation using a drill bit, such as an earth-boring rotary drill bit. Different types of earth-boring rotary drill bits are known in the art, including fixed-cutter bits (which are often referred to in the art as “drag” bits), rolling-cutter bits (which are often referred to in the art as “rock” bits), diamond-impregnated bits, and hybrid bits (which may include, for example, both fixed cutters and rolling cutters). The drill bit is rotated and advanced into the subterranean formation. As the drill bit rotates, the cutters or abrasive structures thereof cut, crush, shear, and/or abrade away the formation material to form the wellbore. A diameter of the wellbore drilled by the drill bit may be defined by the cutting structures disposed at the largest outer diameter of the drill bit.
The drill bit is coupled, either directly or indirectly, to an end of what is referred to in the art as a “drill string,” which comprises a series of elongated tubular segments connected end-to-end that extends into the wellbore from the surface of the earth above the subterranean formations being drilled. Various tools and components, including the drill bit, may be coupled together at the distal end of the drill string at the bottom of the wellbore being drilled. This assembly of tools and components is referred to in the art as a “bottom hole assembly” (BHA).
The drill bit may be rotated within the wellbore by rotating the drill string from the surface of the formation, or the drill bit may be rotated by coupling the drill bit to a downhole motor, which is also coupled to the drill string and disposed proximate the bottom of the wellbore. The downhole motor may include, for example, a hydraulic Moineau-type motor having a shaft, to which the drill bit is mounted, that may be caused to rotate by pumping fluid (e.g., drilling mud or fluid) from the surface of the formation down through the center of the drill string, through the hydraulic motor, out from nozzles in the drill bit, and back up to the surface of the formation through the annular space between the outer surface of the drill string and the exposed surface of the formation within the wellbore. The downhole motor may be operated with or without drill string rotation.
A drill string may include a number of components in addition to a downhole motor and drill bit including, without limitation, drill pipe, drill collars, stabilizers, measuring while drilling (MWD) equipment, logging while drilling (LWD) equipment, downhole communication modules, and other components.
In addition to drill strings, other tool strings may be disposed in an existing well bore for, among other operations, completing, testing, stimulating, producing, and remediating hydrocarbon-bearing formations.
Cutting elements used in earth boring tools often include polycrystalline diamond compact (often referred to as “PDC”) cutting elements, which are cutting elements that include so-called “tables” of a polycrystalline diamond material mounted to supporting substrates and presenting a cutting face for engaging a subterranean formation. Polycrystalline diamond (often referred to as “PCD”) material is material that includes inter-bonded grains or crystals of diamond material. In other words, PCD material includes direct, intergranular bonds between the grains or crystals of diamond material.
Cutting elements, also referred to merely as “cutters” in the art, are often mounted on body a drill bit by brazing. The drill bit body is formed with recesses therein, commonly termed “pockets,” for receiving a substantial portion of each cutting element in a manner which presents the PCD layer at an appropriate back rake and side rake angle, facing in the direction of intended bit rotation, for cutting in accordance with the drill bit design. In such cases, a brazing compound is applied between the surface of the substrate of the cutting element and the surface of the recess on the bit body in which the cutting element is received. The cutting elements are installed in their respective recesses in the bit body, and heat is applied to each cutting element via a torch to raise the temperature to a point high enough to braze the cutting elements to the bit body in a fixed position but not so high as to damage the PCD layer.
A drill bit employing PDC cutting elements is conventionally rotated under applied weight on bit (WOB), and the PDC cutting elements across the drill bit travel at a particular rotational speed (e.g., in rotations per minute). However, a linear speed of the PDC cutting elements near a longitudinal axis of the drill bit travel at a relatively slow linear speed, while a linear speed of the PDC cutting elements more distant from the longitudinal axis travel at a relatively fast linear speed, proportional to a distance from the longitudinal axis, for a given rotational speed of the bit. Accordingly, the PDC cutting elements near the longitudinal axis may cut (i.e., shear) less formation material than the PDC cutting elements distant from the longitudinal axis, slowing the rate of penetration (ROP) of the bit. In addition, due to the significantly different linear speeds of PDC cutting elements near the longitudinal axis versus those distant therefrom, cutting element wear may not be uniform across the drill bit.